The present invention relates to methods of interpreting borehole logging data to determine the presence of hydrocarbons in underground formations.
Qualitatively identifying fluid type of formations based on log curves before further data processing and interpretation is often the key to successful formation evaluation. A petrophysicist will often wish to identify qualitatively the fluid type (hydrocarbon or water) of a formation first and then quantitatively compute various physical properties (such as mineralogy, porosity, saturation, intrinsic and phase permeabilities) of the formation using this knowledge of fluid type to guide the interpretation.
There are presently three main methods for qualitatively identifying fluid type of underground formations: a) electrical resistivity absolute value method, b) three resistivities invasion profile method and c) NMR method. These three methods each have their own advantages weak points and application ranges, and each of them can only be used in certain conditions.
a) Resistivity Absolute Value Method(RAV-M)
The RAV-M is a method which identifies the fluid type of formations according to the deep investigating resistivity log readings in different formations or different parts of one formation (see FIG. 1). The required logs by RAV-M are deep investigating resistivity Rd, effective porosity PHIe and clay volume Vcl. FIG. 1 shows the variation with depth of Rd, PHIe and Vcl when passing from a hydrocarbon zone HC to a water zone W. The required assumption by RAV-M is that the Rw values (the resistivity of formation water) in the different formations or different parts of one formation associated with the analysis are equal. The required working conditions are that the PHIe and Vcl in different formations or different parts of one formation associated with the analysis are equal and there is at least one formation (or one part of a formation) which is hydrocarbon-bearing and another formation (or part of a formation) which is water bearing. The advantage of this method is that it requires only measurement of Rd, PHIe and Vcl for identifying the fluid type of the formation(s). The weak points of this method are: i) the working condition that PHIe and Vcl in different formations or different parts of one formation associated with the analysis are equal is sometimes hard to meet, ii) the working condition that there is at least one formation (or part of a formation) which is hydrocarbon-bearing and another formation (or part of a formation) which is water bearing is normally hard to meet, and iii) the required assumption that Rw values in different formations or different parts of one formation associated with the analysis are equal is usually too hard to meet.
b) Three-Resistivity Invasion Profile Method(TRIP-M)
The TRIP-M is a method which identifies the fluid type of formations according to the order of three resistivity logs with deep, medium and shallow investigating depth (invasion profile) in a single formation (see FIG. 2). The required logs by TRIP-M are three resistivity logs with deep, medium and shallow investigating depth Rd, Rm, Rs and spontaneous electrical potential log SP. FIG. 2 shows the variation of these over depth for a hydrocarbon zone HC and a water zone W. The required working conditions are that the mud must be fresh water-based or oil-based mud, the ratio of the mud filtrate resistivity Rmf and the formation water resistivity Rw must be great than 1, and there must be an invasion profile existing which does not contain a low resistivity annulus and can be investigated by the three resistivity logs. The advantages of this method are that the method requires only Rd, Rm, Rs and SP for identifying the fluid type of formations, it does not need to know Rw, and does not need the working condition that are at least one formation (or part of a formation) is hydrocarbon-bearing and another formation (or part of a formation) which is water-bearing. The weak points of this method are that the required working conditions by this method cannot be met in many cases.
c) Nuclear Magnetic Resonance Method (NMR-M)
NMR-M is a method which identifies the fluid type of formations according to the difference between two T2 spectrums, one measured with long wait time and another measured with short wait time). FIG. 3 shows that variation of the T2 spectra for a hydrocarbon zone HC and a water zone W. The required working conditions of the NMR-M are that there is a certain amount of hydrocarbon in the zone of investigation of the NMR tool (which is usually the flushed zone) and the physical properties of the hydrocarbon in the formations should be understood to a certain degree. Differential spectrum processing with appropriate software is required. The advantages of this method are that the method requires only two T2 spectrums for identifying the fluid type of formations, and does not need other working conditions. The weak points of this method are that the required working conditions cannot be met in many cases either because there is usually little residual hydrocarbon in the flushed zone (especially for the light oil or gas reservoirs of low porosity) or it is hard to know the physical properties of the hydrocarbon in the formations. Another weak point of this method is that the differential spectrum analysis is a complex computation rather than a quick qualitative analysis.
Besides the three methods mentioned above, there are a few other methods for identifying fluid type of formations such as formation pressure gradient method (FPG-M), carbon/oxygen method (C/O-M) and time-lapse method (TL-M). These methods are very useful sometimes, but they are not used very often either because the required logging services are not available or because the required working conditions are hard to meet or because they are not suitable for quick qualitative analysis or because length of logging time and the high cost restrict their extensive applications.
The method according to the present invention (called xe2x80x9cResistivity-Porosity Correlation Methodxe2x80x9d or xe2x80x9cRPC-Mxe2x80x9d) is a method which identifies the fluid type of formations according to the correlation between the variation trend of electrical resistivity with depth and the variation trend of porosity with depth.
The present invention provides a method for determining the nature of a formation fluid surrounding a borehole, comprising:
a) determining the rate of change with depth of a resistivity parameter of the formation surrounding the borehole;
b) determining the rate of change with depth of a porosity parameter of the formation surrounding the borehole;
c) determining a comparison of the rate of change with depth of a resistivity parameter and the rate of change with depth of a porosity parameter for a given depth in the borehole; and
d) using the comparison to determine the nature of the fluid in the formation surrounding the borehole at that depth (or in a given depth window).
The resistivity parameter is preferably a deep resistivity (Rd) measurement made by any suitable resistivity logging tool. The porosity parameter is preferably a measurement of total porosity (PHIt) such as can be made by Schlumberger""s CMR magnetic resonance logging tool.
One embodiment of the invention includes determination of the rate of change with depth of two parameters relating to porosity, preferably the total porosity (PHIt) and the free fluid porosity (PHIff), the rates of change of these two parameters being compared with the rate of change with depth of the resistivity parameter to determine the fluid type.
The comparison of rates of change can be made in either direction, either with increasing depth or decreasing depth, provided that the direction of the rate of change of the parameters is the same. In this application, unless otherwise indicated, all changes and rates of change are made with increasing depth. However, the invention includes the reverse situation (e.g. if parameters are compared as having positive and negative rates of change of with increasing depth, this also includes negative and positive rates of change with decreasing depth, or positive and negative rates of change of with decreasing depth. etc.).
The fluid types of interest are water and hydrocarbon. The method preferably outputs the comparison as a value, the magnitude of which indicating the size of the comparison and the sign (or some other indicator) indicating the nature of the fluid. The magnitude can be used as an estimate of the accuracy (confidence) of the determination of the fluid type. The estimation output can also be corrected by know physical laws, e.g. hydrocarbon always being above water in a given fluid bearing bed.